April 2014

ShaleTech: Barnett shale

Production peaking for now, but potential remains strong

Mike Slaton / Contributing Editor
Is the sun rising or setting on the venerable Barnett shale? While some of the past’s biggest players are exiting the play, other operators see opportunity. New estimates of 44 Tcf of recoverable reserves point to a brighter future somewhere down the road. Photo courtesy of EnerVest Ltd.

Fanning out west of Dallas-Fort Worth, the wells of the Barnett shale harken back to the beginning of the unconventional boom. With efforts today focused on liquids, activity targeting Barnett gas continues to diminish. Major gas reserves and marginal gas prices have led many of the oldest and biggest players to shift their resources elsewhere. Others see opportunity, and are drilling ahead.

The rigs drilling the Barnett shale, most of them anyway, have moved on. So has the conversation. Few operators are talking about the once white-hot Barnett, which blazed the trail for unconventional gas production with the novel combination of long horizontal wellbores and hydraulic fracturing. While it ranks as the second largest, shale dry gas producer behind the Marcellus, and ahead of the fast-growing Eagle Ford, production peaked in 2012—at least from the current perspective. New estimates of the Barnett’s huge gas reserves empathically deny the current demise of the so-called granddaddy of unconventional production, and promises that there is more to come. What stands between the Barnett and a return to glory is the price of gas.

Stale statistics. In the meantime, activity remains anemic. The rig count in the Barnett shale fluttered and stuttered over the past year, from a high of 31 rigs in the first quarter of 2013, to a 22-rig, 12-year low in December, according to RigData’s count for major unconventional plays. Just 19 active rotary rigs were at work in early February, with Devon, EOG, Pioneer and WBH Energy leading the effort—each with less than a handful of rigs making hole. A bounce to 23 rigs in early March hardly made amends. In stark contrast, the Eagle Ford shale to the south of the Barnett is hugely busy, with a tally of 211 rigs in early March.

The Baker Hughes tally of rigs running is similarly low, with a count of 39 for the week of March 14 in the Texas Railroad Commission (RRC) districts that comprise the Barnett. There were 19 active rigs in District 9, 10 rigs in District 5, and 10 rigs in District 9.

Permits point to a continuing trend, Fig. 1. For early 2014, the RRC issued 131 Barnett shale permits through February, a low not equaled since the 1999–2001 period. But those early permits were the leading edge of a nine-year ramp-up to a 2008 peak of 4,065 permits. Permits issued in 2012 staggered to a low of 940—242 fewer than 2011.


Fig. 1. The RRC issued just 131 Barnett shale permits during early 2014.


The well count is tapering off accordingly. It has not yet fallen, but an apogee appears close at hand. Since 1999, the Barnett well count has risen steeply from 534 to 17,494 in 2013. That includes a one-year jump of 3,594 wells from 2008 to 2009. But the curve is bending slowly back to earth. The 2013 increase is 784 wells ahead of 2012, which was 840 wells ahead of 2011.

Gas production (Fig. 2) topped out in 2012 at 5,745 MMcfd, and then dropped to 5,306 MMcfd in 2013. Oil now appears the favorite, even in the gassy Barnett. In January 2013, the RRC counted 151 oil completions and just 60 gas completions, compared to 42 oil completions and 98 gas completions in January 2012.


Fig. 2. Barnett gas production peaked in 2012 at 5.745 MMcf, and then dropped to 5,306 MMcf the next year.


The RRC’s November 2012 summary of Barnett shale activity counted 16,530 total gas wells and 2,457 permitted locations in Districts 5, 7B and 9. In the period of January–November 2012, production was 1,770 Bcf, accounting for about 31% of total Texas gas production.

As of Novembr 2012, there were 235 operators in the play, Table 1. The top10 gas operators for January through November 2012 included Devon Energy (453.6 Bcf) Chesapeake Operating (433.7 Bcf), and XTO Energy (275.9 Bcf).


Table 1. The top 10 barnett gas operators for january through november 2012.



Play potential. While dogged by low gas prices, the Barnett’s potential is considerable. The Bureau of Economic Geology at The University of Texas at Austin recently forecast a cumulative 44 Tcf of recoverable reserves with an annual production decline slowing from a current peak of 2 Tcf per year to about 900 Bcf per year by 2030. The study assumes an average natural gas price of $4/Mcf. The U.S. national average gas price in mid-March was about $5.50/Mcf.

Among major U.S. shale gas provinces, the Barnett is a steady second behind the fast-growing Marcellus. Monthly dry shale gas production for January 2014 from the Barnett averaged 4.454 Bcfgd, according to figures assembled by the U.S. EIA, Fig. 3. The Marcellus, in Pennsylvania and West Virginia, posted production of 10.919 Bcfgd, while the Eagle Ford in south Texas was in third place with 3.917 Bcfgd.


Fig. 3. Among major U.S. shale gas provinces, the Barnett is second to the Marcellus.


The Barnett Shale formation, designated by the RRC as the Newark East field, covers an estimated 5,000 sq mi (13,000 km²) and consists of 25 core and non-core counties.

The 1981 discovery of the Newark East field by Mitchell Energy set in motion larg-scale, commercial shale gas production. The successful combination of horizontal drilling and hydraulic fracturing in the Barnett formation ultimately led to development of unconventional assets in the Fayetteville shale in Arkansas, and quickly moved on to other shale plays, including the Haynesville, Marcellus, Woodford and Eagle Ford.

Significant drilling activity did not begin until gas prices increased in the late 1990s. In 1993, the Barnett shale produced 11 Bcfg. In 2011, the formation produced 1.93 Tcfg or 5.3 Bcfgd, an increase of 190% over production levels just five years earlier, according to figures assembled by the Institute for Energy Research (IER). More than 15,000 wells have been drilled in the Barnett to date, Fig. 4.


Fig. 4. Significant drilling activity did not begin until gas prices increased in the late 1990s, with most of the growth occurring in horizontal drilling.


The economic impact has been huge. A 2011 economic impact analysis by the Perryman Group attributes approximately 38% of the North Texas region’s economic growth since 2011 to Barnett production. In that year, Barnett production added an estimated $11.1 billion to the region’s economy and supported more than 100,000 jobs. On a statewide basis, Barnett production added almost $13.7 billion to the Texas economy in 2011 and supported more than 119,000 jobs. Local and state tax revenue from Barnett shale activity is estimated to have totaled $1.6 billion for 2011 alone.

Operating positions. It’s quiet out there. Among the publically held big names operating in the region, references to the Barnett are small to nil. Most are marginally active on the drilling scene—if at all. Some, such as Pioneer Natural Resources and Carizzo O&G, have sold or are selling their holdings. Others, such as EnerVest and Quicksilver Resources, are buying, signing on partners, and running modest drilling programs.

Devon Energy, the biggest producer in the Barnett and the legacy holder of Mitchell Energy’s original leases, continues to reduce spending in the gas shale. In 2014, the company will spend $600 million to drill approximately 200 wells, in a program that includes the Barnett and two plays in Oklahoma’s Anadarko basin, the Cana and Granite Wash. The Barnett drilling program will employ two rigs.

Last year, Devon spent about $500 million in the Barnett, alone, and drilled 172 wells. The company has more than 600,000 net acres in the Barnett, with fourth-quarter 2013 production in excess of 1.3 Bcfged

Reflecting a shift toward liquids and crude, the lower activity contrasts with Devon’s recent acquisition of 82,000 net acres in the Eagle Ford. Plans are to invest approximately $1.1 billion in 2014, and drill more than 100 wells.

A scenic point of interest for those millions of people traveling through DFW International Airport may be one of Chesapeake Energy’s rigs drilling Barnett shale prospects. According to airport officials, there are currently 112 natural gas wells producing on its DFW property. Jointly owned by the cities of Dallas and Fort Worth, the airport in 2013 generated $5,326,417 in total royalty revenue from natural gas production. 

Chesapeake is the sole operator at the airport, which covers 26.9 sq mi. The Chesapeake lease was established in 2006, with an up-front bonus of $186 million. The price of gas has since slowed the pace of drilling. In 2013, Chesapeake received approval to delay its DFW program. Instead of drilling six wells in 2013 and eight in 2014, they instead plan to drill six wells in 2014 and eight in 2015.

Elsewhere in the gas-rich Barnett, Chesapeake continues to tamp down its activities in favor of oil prospects, Fig. 5. Its estimated 2014 E&P CAPEX shows Barnett expenditures at less than 5% of the total outlay—on par with expenditures in the Marcellus South play, and far below the roughly 35% targeted in the Eagle Ford.




Fig. 5. These charts from a Chesapeake Energy February 2014 investor presentation reflect a reality for many operators, who are shifting money and activity from the Barnett’s dry gas to richer, wetter prospects. 


In 2014, the company expects to lean heavily toward liquids and oil, with as many as 48 dedicated rigs, versus 14–17 rigs drilling gas prospects. A single rig will be at work in the Barnett for every 15 to 18 planned in the Eagle Ford. At the end of 2013, Chesapeake’s inventory included 58 wells in the Barnett.

EnerVest has a more positive outlook. It has acquired more than $3 billion of oil and gas properties in the Barnett since December 2010. The company plans continued growth in the formation through a combination of acquisitions and drilling. Projected 2014 capital expenditures for drilling total about $173 million to drill approximately 70 wells, mainly in rich gas areas. This should equate to a two-drilling-rig program throughout the year, EnerVest reported.

In the ranks of the 25 largest U.S. oil and gas companies, EnerVest has more than 28,000 wells across 17 states, 4.8 million acres under lease, and more than $9 billion in assets under management. A December 2011 EnerVest presentation to IPAA reported a production mix of 48% shale and 40% tight rock, with the balance from conventional and coalbed assets. The company counted itself as the sixth largest producer in the Barnett, with 1,101 wells and more than 100,000 gross acres. Total production was approximately 238 MMcfed (1,200 bopd and 9,300 bpd of NGLs).

Their 2011 drilling program resulted in 43 wells, and 100 wells were planned in 2012, related to the acquisition of Encana’s Barnett shale assets. The $975-million transaction involved 700 wells producing 125 MMcfgd. A refrac program included six wells in 2011, and 26 were planned in 2012.

Mark Houser, executive vice president and COO of EnerVest, observed at the time of the acquisition, “That position, along with another small position we’re acquiring simultaneously from a private company, is going to more than double our production in the Barnett shale and will make us about the number six producer in the basin.”

In November 2013, the company announced acquisition of $1.4 billion in producing properties from seven different sellers. Included were $240 million in Barnett assets, in two deals that added 251 Bcfe to its proved gas reserves in the play. The acquisition involved $218 million for 9,511 net acres and 234 Bcfe of proved reserves from Carrizo O&G.

EOG says its 2014 game plan is “all about oil.” The company plans to grow crude oil production by 27%, and total production by 11.5%, year to year. With about 79% of its estimated 2014 Capex budget dedicated to exploration and development, the majority will be spent in three oil plays—the Eagle Ford, Bakken, and the Delaware basin’s Leonard play. EOG advises that there will be no North American dry gas drilling—which largely excludes the Barnett. The company has 298,000 net acres in the Barnett’s gas and combo plays.

Pioneer Natural Resources, which entered the Barnett in 2007, is continuing to show its assets in the play as discontinued operations. In January 2013, the company announced that it had ceased efforts to sell the properties that had begun activity in September 2012. Several bids were received, but none were attractive to Pioneer. Pioneer retained operatorship of the asset, which consists of about 155,000 gross acres in the play, much of it in the liquids-rich Barnett shale combo play. Pioneer was operating one rig in the play during 2013.

The divestiture, along with the sale of Alaskan assets, is aimed at reallocating capital to a higher-return Spraberry/Wolfcamp horizontal drilling program in the Permian basin.

Quicksilver Resources, headquartered in Fort Worth, Texas, says the Barnett shale formation is the foundation for the company’s growth. The company has leased approximately 88,000 net acres (after a working interest sale to Tokyo Gas) within the company’s defined core fairway. With approximately 60% of the acreage currently held by production, the company expects to achieve continued growth in production and reserves in Texas, where officials believe approximately 1–2 Tcf of total potential gas resources have been identified. The joint venture partnership with Tokyo Gas, which closed April 2013, will continue developing the Barnett, with Quicksilver as the operator. The company says there are no plans to increase CAPEX initially, or change near-term development plans. This is Tokyo Gas’ first investment in U.S. shale. They purchased 25% interest across the asset.

Quicksilver’s 2013 capital plan totaled $129 million. The Barnet shale made up 8% of total expenditures. The company, which says it is focused on unconventional formations in North America, sees the Fort Worth basin’s Barnett shale formation as a high-quality, low-risk asset. Quicksilver has 155,533 gross acres and 1,010 gross producing wells in the basin. Average net production in the third quarter of 2013 was 67 MMcfed.

In a December 2013 analyst presentation, Quicksilver advised that its CAPEX budget was aimed at maintaining flat Barnett production in its Alliance, Southern liquids-rich acreage, and Lake Arlington and Hill Country acreage. Development plans included drilling up to six wells in fourth-quarter, 2013, and 150 workovers in 2013. The company expected to utilize one rig throughout 2014. Its Fort Worth basin workover program averages about $30,000 to $35,000 per well to add 500 Mcfd of production. The workovers, at current prices, pay back in one to two months.

In September 2013, Carrizo Oil & Gas announced the sale of its remaining Barnett shale assets, about 9,000 net acres, primarily in southeastern Tarrant County. EnerVest acquired the properties. Year-end 2012 proved reserves of the asset were 303.5 Bcf. Current net production from the assets was approximately 44 MMcfgd.

In announcing the sale, S. P. “Chip” Johnson IV, Carrizo’s president and CEO, commented, “This is a bittersweet day for Carrizo, as the Barnett shale started the company’s transformation into an unconventional resource player back in 2003.” He characterized the sale as a natural step in the company’s continued shift toward oil and liquids-rich plays. wo-box_blue.gif



The Barnett shale/Central Texas and Anadarko/Granite Wash production areas will gain additional access to market via the new Texas Express NGL pipeline. Two new NGL-gathering systems link natural gas processing plants to the Texas Express. The gathering systems were built by a joint venture comprised of Enterprise, Enbridge Energy Partners and Anadarko.

The Texas Express pipeline from Skellytown, Texas, to the NGL fractionation and storage complex in Mont Belvieu, Texas, started service in October 2013. Owned by Enterprise Products Partners L.P., Enbridge Energy Partners, L.P., Anadarko Petroleum Corporation, and DCP Midstream Partners LP, the 583-mi., 280,000-bpd Texas Express pipeline gives producers in West and Central Texas, the Rocky Mountains, southern Oklahoma, the Mid-continent and the Denver-Julesburg basin, much-needed takeaway capacity for growing NGL volumes, and improved access to the largest NGL trading hub, located along the Gulf Coast. wo-box_blue.gif

About the Authors
Mike Slaton
Contributing Editor
Mike Slaton is a contributing editor.
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